1. Field of the Disclosure
Embodiments of the present disclosure relate generally to drilling boreholes, or wellbores, through subsurface formations. More particularly, embodiments of the present disclosure relate to a method and a system for controlling the rate of release of a drillstring to maintain a rate of penetration that is within a selected set of parameters during drilling.
2. Background Art
Drilling wells in subsurface formations for oil and gas wells is expensive and time consuming. Formations containing oil and gas are typically located thousands of feet below the earth's surface. Therefore, thousands of feet of rock and other geological formations must be drilled through in order to establish production. While many operations are required to drill and complete a well, perhaps the most important is the actual drilling of the borehole. The costs associated with drilling a well are primarily time dependent. Accordingly, the faster the desired penetration depth is achieved, the lower the cost for drilling the well. However, cost and time associated with well construction may increase substantially if wellbore instability problems or obstacles are encountered during drilling. Successful drilling requires achieving a penetration depth as fast as possible but within the safety limits defined for the drilling operation.
Achieving a penetration depth as fast as possible during drilling requires drilling at an optimum rate of penetration (“ROP”). The ROP achieved during drilling depends on many factors including, but not limited to, the axial force applied at the drill bit known in the industry as the weight on bit (“WOB”). As disclosed in U.S. Pat. No. 4,535,972 issued to Millheim, et al., ROP generally increases with increasing WOB until a maximum beneficial weight on bit is reached, thereafter decreasing with further weight on bit. Thus, generally for a given wellbore, a particular WOB exists that will achieve a maximum ROP.
However, the ROP may be dependant on various factors in addition to the WOB. For example, the ROP may depend upon the geological composition of the formation being drilled, the geometry and material of the drill bit, the rotational speed (“RPM”) of the drill bit, the amount of torque applied to the drill bit, and the pressure and rate of flow of drilling fluids in and out of the wellbore. One of ordinary skill in the art will appreciate that because of these (and other) drilling variables, an optimal WOB for one set of drilling conditions may not be optimal for another set of conditions.
Referring initially to FIG. 1, a rotary drilling system 10 including a land-based drilling rig 11 is shown. While drilling rig 11 is depicted in FIG. 1 as a land-based rig, it should be understood by one of ordinary skill in the art that embodiments of the present disclosure may apply to any drilling system including, but not limited to, offshore drilling rigs such as jack-up rigs, semi-submersible rigs, drill ships, and the like. Additionally, although drilling rig 11 is shown as a conventional rotary rig, wherein drillstring rotation is performed by a rotary table, it should be understood that embodiments of the present disclosure are applicable to other drilling technologies including, but not limited to, top drives, power swivels, downhole motors, coiled tubing units, and the like.
As shown, drilling rig 11 includes a mast 13 supported on a rig floor 15 and lifting gear comprising a crown block 17 and a traveling block 19. Crown block 17 may be mounted on mast 13 and coupled to traveling block 19 by a cable 21 driven by a draw works 23. Draw works 23 controls the upward and downward movement of traveling block 19 with respect to crown block 17, wherein traveling block 19 includes a hook 25 and a swivel 27 suspended therefrom. Swivel 27 may support a Kelly 29 which, in turn, supports drillstring 31 suspended in wellbore 33.
Typically, drillstring 31 is constructed from a plurality of threadably interconnected sections of drill pipe 35 and includes a bottom hole assembly (“BHA”) 37 at its distal end. Bottom hole assembly 37 may include stabilizers, weighted drill collars, formation measurement devices, downhole drilling motors, and a drill bit 41 connected at its distal end. It should be understood that the particular configuration and components of BHA 37 are not intended to limit the scope of the present disclosure.
During drilling operations, drillstring 31 may be rotated in borehole 33 by a rotary table 47 that is rotatably supported on rig floor 15 and engages Kelly 29 through a Kelly bushing. Alternatively, a top drive assembly (not shown) may directly rotate and longitudinally displace drillstring 31 absent Kelly 29. The torque applied to drillstring 31 by drilling rig 11 to rotate drillstring 31 is often referred to as rotary torque or drilling torque. Furthermore, many BHAs 37 may include sensors to measure the amount of torque applied to drill bit 41, known in the industry as the torque on bit.
Drilling fluid, often referred to as drilling “mud,” is delivered to drill bit 41 through a bore of drillstring 31 by mud pumps 43 through a mud hose 45 connected to swivel 27. In order to drill through a formation 40, rotary torque and axial force may be applied to bit 41 to cause cutting elements disposed on bit 41 to cut into and break up formation 40 as bit 41 is rotated. Cuttings produced by bit 41 are carried out of borehole 33 through an annulus formed between drillstring 31 and a borehole wall 36 by the drilling fluid pumped through drillstring 31.
As is well known to those skilled in the art, the weight of drillstring 31 may be greater than the optimum or desired weight on bit 41 for drilling. As such, part of the weight of drillstring 31 may be supported during drilling operations by lifting components of drilling rig 11. Therefore, drillstring 31 may be maintained in tension over most of its length above BHA 37. Furthermore, because drillstring 31 may exhibit buoyancy in drilling mud, the total weight on bit may be equal to the weight of drillstring 31 in the drilling mud minus the amount of weight suspended by hook 25 in addition to any weight offset that may exist from contact between drillstring 31 and wellbore 33. The portion of the weight of drillstring 31 supported by hook 25 is typically referred to as the “hook load” and may be measured by a transducer integrated into hook 25.
Furthermore, drilling system 10 may include at least one pressure sensor 38, a processor 34, and a drillstring release controller 46. Processor 34 may be any form of programmable computer including, but not limited to, a general purpose computer, a programmed-for-purpose computer, a programmable logic controller (“PLC”), an embedded processor, or a software program. Processor 34 may be operatively connected to drillstring release controller 46 in the form of a brake band controller or a hydraulic/electric motor coupled to drawworks 23.
As shown, pressure sensor 38 may be provided in BHA 37 located above drill bit 41. As such, pressure sensor 38 may be operatively coupled to a measurement-while-drilling system (not shown) in bottom hole assembly 37. Additional pressure sensors may be located throughout drillstring 31. Pressure measurements made by pressure sensor 38 may be communicated to equipment at the earth's surface including a processor 34 using known telemetry systems including, but not limited to, mud pressure modulation, electromagnetic transmission, and acoustic transmission telemetry. Alternatively, pressure measurements may be communicated along an electrical conductor integrated into drillstring 31.
It has been shown that the monitoring of borehole fluid pressures may aid in the diagnosis of the condition of the wellbore and help avoid potentially dangerous well control issues. Annular pressure measurements during drilling, when used in conjunction with measuring and controlling other drilling parameters, have been shown to be particularly helpful in the early detection of events such as sticking, hanging or balling stabilizers, mud problem detection, detection of cutting build-up, and improved steering performance. One value used to represent the pressure is a parameter known as the differential pressure. The differential pressure is defined as the difference in pressure between the supplied drilling fluids and the returning drilling fluids. The differential pressure is commonly referred to in the drilling industry as DeltaP or ΔP.
Historically, measuring and controlling drilling parameters included a system in which a feedback value for each drilling parameter was provided by sensors along the drill line. These feedback values were then compared to setpoint values that were set by the drilling operator and when an issue arose, defined by the drilling operation limits, the operator or system would switch and adjust the drilling parameter accordingly. Some other important parameters for drilling include WOB and drilling torque. Furthermore, in systems having multiple monitored parameters, the operator would formerly switch his or her focus on only one parameter at a time. As such, while many parameters may be “monitored” at any given time, only one would “control” the release of the drillstring. Therefore, a need exists for a drilling system to allow several drilling parameters to affect the release of the drillstring simultaneously without such switching.